1. Field of the Invention
The present invention relates to a method and apparatus for preventing hydrate formation in pipelines which carry mixtures of hydrocarbons and water.
2. Description of the Prior Art
At low temperatures and high pressures, hydrates may form in full wellstream fluids containing water. Full wellstream fluids, also referred to as produced fluids, are unprocessed fluids from an oil and gas reservoir. Full wellstream or produced fluids typically include light gases, such as methane, ethane, propane, butane, carbon dioxide, hydrogen sulfide and water. The water present in full wellstream fluids can combine with the light gases, under certain conditions, to form hydrates.
Hydrates are crystalline solids. If the produced fluids from a particular reservoir include water, the light gases and the water in the produced fluids may combine to form hydrates. If hydrates form in a pipeline carrying produced fluids from an oil and gas well they can cause serious problems. Hydrates, for example, can completely plug piping, valves or other production equipment, thereby resulting in costly production delays.
High pressure in the presence of low temperature are the conditions which may cause the light gases and water in full wellstream fluids to combine and form hydrates. For example, at a temperature of 4.5.degree. Centigrade (40.degree. Fahrenheit) and a pressure of 105,500 Kg per square meter (150 psia) hydrates could form in a pipeline system containing full wellstream fluids.
These conditions are most commonly encountered in offshore operations where it is necessary to transport produced fluids in a long vertical pipeline, such as a riser system. The technology for drilling and completing oil and gas wells offshore has progressed to permit production from locations in deeper and deeper water. Typically, a riser system is used to vertically transport produced fluids to or from the ocean floor. A riser system is essentially a specially designed vertical pipe capable of withstanding the forces inherent to the offshore environment.
The weight of the fluid in the riser causes hydrostatic pressure. When the riser system is full of produced fluids, generally a column of liquid is formed with a height equal to the vertical length of the riser. Hydrostatic pressure is associated with any column of liquid. The weight of the liquid above a given point in the column of liquid increases the force per unit area at the given point. Consequently, as the height of the column of liquid in the riser increases, the hydrostatic pressure at the lowermost point in the pipeline also increases. The pressure in the lowermost portion of the pipeline can become quite high as the result of a long riser full of hydrocarbon liquid. Generally if the riser is 107 meters (350 feet to 400 feet) or longer, the hydrostatic pressure resulting from the column of produced fluids will be high enough so hydrates could form if the fluid temperature lowers into the hydrate formation range.
The temperature of the produced fluids is most likely to lower into the hydrate formation range if the flow of produced fluids is stopped for a prolonged period. When the flow stops for a prolonged period the produced fluids eventually cool to the temperature of the surroundings. The water temperature in the ocean decreases as depth beneath the ocean surface increases. The temperature at the floor of the ocean depends on surface conditions, currents and the depth below the surface. However, at depths below 107 meters (350 feet) the temperature at the ocean floor typically ranges from 2.degree. Centigrade (35.degree. Fahrenheit) to 7.degree. Centigrade (45.degree. Fahrenheit). The temperatures at these depths in combination with the hydrostatic pressure produced in a riser of that length provide the conditions conducive to hydrate formation.
In offshore operations there are numerous pipeline system configurations which include a long vertical riser. The particular pipeline system configuration chosen is usually dictated by economics. For example, as opposed to building a platform for each well, the produced fluids from several subsea wells may be transported up to a satellite platform. To keep the facilities on the satellite platform at a minimum, the produced fluids may then be transferred by pipeline to a central platform for processing. The transfer pipeline would run along the ocean floor and include two risers, one to transport the produced fluids to the ocean floor and another to transport the fluids from the ocean floor to the central platform. Other pipeline system configurations having a riser include transporting produced fluids from one subsea well to a platform for processing, and transporting produced fluids from an underwater manifold center, serving as a collection point for several subsea wells, to a platform for processing.
There generally are less problems with the formation of hydrates under normal operating conditions than during shutdown conditions since the full wellstream fluids usually do not reach the relatively low temperatures at which hydrates form. The temperature of fluids produced from a reservoir usually ranges from 43.degree. Centigrade (110.degree. Fahrenheit) to 149.degree. Centigrade (300.degree. Fahrenheit). Heat is lost from the full wellstream fluids as they pass up the wellbore and through the pipeline system. However, as long as the full wellstream fluids flow continuously, they generally do not enter the hydrate formation range. If the heat loss would cause the temperature of the fluids to drop into the hydrate formation range, the pipeline can be insulated to lessen the heat loss and prevent hydrate formation.
In the past, several methods have been used to prevent hydrate formation in subsea pipeline systems which transport produced fluids which include water. One method involves injecting a chemical hydrate inhibitor, such as methanol or glycol, into the pipeline. These chemicals dissolve in the free water in the produced fluids and lower the temperature at which hydrates will form. The concentration of inhibitor in the water determines the depression of the hydrate formation temperature. This method has several drawbacks. Because operators never know when an emergency shutdown will occur, all the produced fluids passing through the pipeline must be treated. This is the only way, using this particular method, to assure that the produced fluid in the pipeline system after an emergency shutdown will not form hydrates. Extremely large quantities of methanol or glycol are needed to continuously treat a full wellstream fluid containing significant quantities of water. Injecting chemical hydrate inhibitors into the pipeline will therefore usually be economically impractical because of the large quantity of chemicals required and the costs of transporting the chemicals to an offshore location.
In some cases, hydrate inhibiting chemicals can be economically recovered after their use, such as when treating a water saturated gas stream. However, when treating produced liquids that include water, the recovery of chemical hydrate inhibitors is usually economically impractical since, in most cases, the hydrate inhibitors can not be recovered economically. The salt present in water from the reservoir contaminates the chemicals and makes the recovery of the chemicals very difficult.
Another method of hydrate prevention consists of displacing the hydrocarbons in the pipeline with fluids that will not form hydrates, such as stabilized crude. Because of the extreme volume of a pipeline system, large quantities of fluids that will not form hydrates are needed which makes this method costly and unattractive. Further, this method is not completely reliable since pumping facilities are required at the ocean surface on one end of the pipeline. During an emergency shutdown power may not be available for the needed pumping facilities.
Another method that may be used is partial processing of the full wellstream fluids from the reservoir before transporting the fluids in a pipeline. Hydrates only form in the presence of water. Therefore, hydrate formation can be prevented by removing water from the produced fluids. Another partial processing method removes light hydrocarbons, which combine with water to form hydrates, from the produced fluids.
Several drawbacks are also associated with partially processing the produced fluids. Costly equipment is needed to partially process the produced fluids. In addition, the equipment requires space, which is at a premium in offshore operations. After partial processing, the removed substances must be stored, disposed of, or transported to another location. If water is removed from the produced fluids it must be treated before disposal. The light gases are of particular concern. The gases must either be transported in a separate pipeline to a processing platform or flared. The gas pipeline is an additional cost and also requires hydrate inhibition if the gas is not dehydrated by partially processing it on the satellite platform. Gases can be flared, however, in some areas flaring is disallowed.
Because of the equipment needed, use of the partial processing methods require a satellite platform. Therefore, partial processing before transportation is not possible when a platform is not used, such as when subsea satellite wells are produced individually or several subsea wells are produced from an underwater manifold center.
Thus, there is a need for an apparatus and method for preventing hydrate formation adaptable to any transfer pipeline, such as from a satellite platform, an underwater manifold center or a subsea well. Furthermore, there is a need for a less costly method which does not require the chemicals or equipment needed to either inject hydrate inhibitors, displace the hydrocarbon fluid or partially process the full wellstream fluids. Furthermore, there is a need for a reliable apparatus and method that will not require a source of power which may be unavailable in an emergency shutdown.